Natural Resources Record Newsletter - Winter 2016-2017

December 2016


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Table of Contents

Changes to Partnership Taxation: Implications for Oil and Gas Businesses
OPEC’s Deal to Cut Production: Global Short and Long-Term Effects
Top Takeaways from the 2016 Oil & Gas Council North America Assembly
Q&A with Steve Franckhauser, HBK Energy
PErspective in Natural Resources


Changes to Partnership Taxation: Implications for Oil and Gas Businesses

By Shuja Akram

It has now been more than a year since President Obama signed the Bipartisan Budget Act (BBA) of 2015 into law, promising major changes to partnership audit and taxation in 2016. With the IRS’s October 2016 release of final and temporary regulations related to liability allocations under IRC Section 752 and disguised sales under IRC Section 707, among others, that promise has been fulfilled—with significant ramifications for oil and gas companies that often rely on partnership structures.

The Basics                     

The regulations introduce several key tax changes for partnerships, with some of those most affecting the natural resources sector including:
  • Tax return due dates move up. Partnership tax returns are now due a month earlier on March 15, as opposed to April 15.
  • New IRS examination rules shift the burden of responsibility for taxes due. If, following an audit, a member of a partnership is found to owe additional taxes, the partnership must pay the amount due. This is effective for the 2018 tax year.
  • Partners may not be considered employees of the partnership via disregarded entity. The IRS has long held that partners cannot be treated as employees of a given partnership and are subject to self-employment tax, effectively increasing the partner’s tax burden and limiting their access to employee benefits. In an effort to work around these downsides, many partnerships have employed their partners through the creation of a “disregarded entity”—typically, a single-member limited liability company the partnership wholly owns. The IRS’s newest guidance aims to crack down on this practice.
  • Debt-financed distributions to partners will now be allocated based on profit allocation ratios to members who have received cash distributions. Under the temporary regulations related to IRC Sections 707 and 752, a partner’s share of any partnership liability for disguised sale purposes is the same percentage used to determine the partner’s share of the partnership’s excess nonrecourse liabilities. This rule applies regardless of whether the liability is recourse or nonrecourse. For purposes of the disguised sale rules, a partner’s share of partnership excess nonrecourse liabilities will be based on the partner’s share of partnership profits. The temporary regulations also provide that, for disguised sale purposes, if another partner bears economic risk of loss with respect to a liability, then no portion of that liability can be allocated to the contributing partner.
  • Partners may no longer compute preformation capital expenditures on an aggregate basis. Also pertaining to disguised sales under IRC Sections 707 and 752, in general, transfers of money or other consideration from a partnership to reimburse a partner for certain capital expenditures and costs incurred by the partner are not treated as part of a disguised sale of property. There is, however, an exception for preformation capital expenditures that typically applies only to the extent that the reimbursed capital expenditures do not exceed 20 percent of the fair market value of the property transferred by the partner to the partnership (the 20-percent limitation). The 20-percent limitation does not apply if the fair market value of the transferred property does not exceed 120 percent of the partner’s adjusted basis in the property at the time of the transfer (the 120-percent test). Under the new guidance, the preformation expenditure exception applies on a property-by-property basis—partners may not use an aggregate value and tax basis—which may limit their ability to take advantage of this exception.
The final and temporary regulations include a number of other provisions with broad applicability to partnerships, ranging from anti-abuse rules and deficit restoration obligations to qualified liability exclusions. And though the timeline for implementation of the new regulations remains in question, partnerships must begin planning now to ensure they understand the impact of these rules on their tax returns—and their partners.

Implications for the Oil and Gas Industry

All partnerships, regardless of sector, are likely to feel some reverberations from these new regulations, as will their tax advisors and preparers. However, the natural resources industry and the oil and gas sector in particular will face some unique challenges—some that may simply create more work for the partnership, and others that will remain major sticking points as the industry works to comply with the new regulations.
The adjustment to the examination process—specifically, the rules requiring underpayments to be calculated at the partnership level—may prove particularly problematic for the oil and gas industry. In general, oil and gas partnerships calculate taxes at the partner level, which in and of itself makes it difficult to adjust for underpayment at the partnership level. However, this is further complicated by the patchwork of tax deductions available to partners in the oil and gas industry, such as depletion expense and the intangible drilling deduction—which the partnership does not compute.

In the case of depletion expenses, tax rules allow partners to use one of two methods (cost or percentage) to compute their deduction for expenses spent on a given oil or gas leasehold, taking whichever results in a higher reduction in taxes owed. The cost method is straightforward and similar to depreciation in that the partner can simply expense the amount of money spent on a given leasehold. The percentage method, however, is far more complicated, and requires the partner to determine how much revenue he or she is receiving from selling the produced oil and gas, and then take 15 percent of the total as the deduction. Unlike the cost method, this restricts the deduction to the partner’s taxable income and does not allow him or her to take a loss on the asset. Similarly, in order to claim a deduction for intangible drilling costs, a partner can choose to either capitalize or expense the costs associated with a leasehold, with implications for the ultimate amount of individual income tax owed.

Partnerships, then, have limited insight into the individual tax position of each partner. If an individual is a partner in multiple ventures, it is difficult for each partnership to assess which computation method that partner is using for his or her deductions, and virtually impossible for a partnership to know the total amount of that individual’s taxable income. Thus, if an IRS audit finds that a partnership owes taxes, the partnership may struggle to identify how to allocate the underpayment.

The accelerated filing date will also place a major burden on oil and gas partnerships. In addition to simply having less time to prepare a tax return, the new timeline does not make much allowance for the complex nature of oil and gas industry partnerships. In the case of exploration and production companies, partnerships generally rely on outside contractors to actually drill and produce oil and gas assets—and it can take time to access essential information from these contractors to facilitate tax preparation.  Some of the same limitations partnerships face when assessing tax liabilities at the partner level—a lack of visibility into taxable income and the way deductions are calculated—apply here as well. Partnerships in the oil and gas industry can also consist of multiple tiers (e.g., if a private equity fund invests in the partnership) that add layers of complexity to the tax preparation process. In other words, partnerships have even less time—just two-and-a-half months from year-end—to gather information from these disparate parties and file their returns.

Exacerbating the new timeline are the latest rules surrounding disguised sales—in particular, the guidance that preformation capital expenditure reimbursements must be calculated on an asset-by-asset basis. For example, prior to the new rules, a $52 million disguised sale of multiple oil and gas assets might yield $10.4 million in reimbursable expenditures (that is, 20 percent of the $52 million). However, under the new guidance, the sale price and reimbursable expenditure of each asset sold must be calculated separately, which creates additional burden for the tax preparer while reducing the reimbursement—perhaps to as little as $2 million, depending on the individual fair market value of each asset.

What’s Next

Several questions about the new regulations remain unanswered, with the final versions of some of these rules still pending and implementation dates unclear. It is also uncertain whether companies will be permitted to adopt these rules ahead of their effective date. Regardless of the lingering questions, however, oil and gas businesses should consult with a tax professional to begin planning—whether that means exploring alternative business structures, or otherwise adjusting their tax preparation procedures to ensure compliance.
In October, BDO’s National Tax Office issued three alerts related to the new partnership regulations. For an in-depth discussion of these regulations and their applicability, refer to our alert addressing disguised sales under IRCS Section 707, our alert relating to the determination of recourse liabilities under Section 752, and our alert discussing the re‑proposed regulations.

Shuja Akram is a tax managing director with BDO USA. He can be reached at [email protected].
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OPEC’s Deal to Cut Production: Global Short and Long-Term Effects

By Charles Dewhurst

OPEC, the 13-member cartel responsible for producing nearly a third of the world’s oil supply, announced a deal to cut oil production on November 30—a landmark decision designed to reverse the two-plus year downward spiral in oil prices. Involving several key players, including oil giants Saudi Arabia and Iran, the deal urged OPEC countries to reduce output by 1.2 million barrels per day (BPD) to 32.5 million BPD.[1] Saudi Arabia will lead the charge and take the highest cut at 486,000 BPD, followed by Iraq and United Arab Emirates. [2] Non-OPEC countries were additionally encouraged to cut 600,000 BPD.

A High-level Monitoring Committee consisting of OPEC oil ministers and assisted by the OPEC Secretariat is charged with ensuring that members carry out the deal’s obligations. The cuts will take effect January 1 and last for six months, with the possibility of another six-month extension.

If anything, the deal signals the desperation the cartel feels after its decision to allow production output to run freely in 2014 backfired, leading to a market oversupply of up to nearly two million barrels a day. [3] Crude oil prices took a hit as a result, falling by more than 70 percent from June 2014 levels at its lowest point over the past two years. [4] OPEC’s deal, then, is long overdue and will have several short-term and long-term effects on the oil and gas industry.

The Short-Term

The short-term effects of the deal are apparent. Hours after the announcement, the industry witnessed a spike in oil prices, an increase in U.S. energy group shares and a general renewed optimism. CNN Money reported a nearly 9 percent increase in crude prices to $49.20 per barrel on the same day. In the days to follow, crude prices topped $50 per barrel for the first time in several months, and industry observers continue to hope that prices will increase to $55-$60 per barrel in early 2017.

Renewed optimism has also sent the shares of U.S. energy groups soaring, with both major onshore producers and smaller energy groups benefiting. Bloomberg Markets reported investors pushing several energy companies into the top 18 spots on the Standard & Poor’s 500 index, increasing the U.S. oil industry’s market value by $81.3 billion in one day. Banks also displayed renewed confidence in energy companies’ ability to repay loans by beginning to release protection reserves set aside earlier this year.

The Long-Term

The longer-term effects of OPEC’s deal remain to be seen. Nevertheless, experts expect an overall increase in oil production from non-OPEC countries looking to capitalize on rising prices and increased demand. The International Energy Agency predicts Brazil, Canada and Kazakhstan will pump more oil in 2017, which could increase total non-OPEC output to 500,000 BPD next year. [5] China, one of the world’s biggest oil importers and a major producer, may also boost its own oil production as it reduces reliance on Saudi oil. The U.S. shale industry—ironically, the industry that OPEC is looking to drive out of business—may also see an uptick in production now that crude oil can be pumped almost as inexpensively in the U.S. as in several OPEC countries. The Permian Basin in Texas and New Mexico is particularly attractive in this regard.

For OPEC, an increase in non-OPEC oil production could have the opposite effect of the deal’s original intent: a loss of global market share and a stem in increasing prices. Thus, while a decreased oil supply may lead to increased prices over the next couple of months, the industry may also see an eventual leveling out of prices, or even potential decreases, as non-OPEC members rush to fill the gap. Goldman Sachs, for example, predicts that crude prices will spike in the first half of 2017 but moderate in the second half, while JP Morgan sees prices rising slowly but steadily quarter after quarter. The overarching question of whether the cuts are even significant enough to offer the boost to oil prices that OPEC needs to be profitable also remains.

Looking Ahead

Many uncertainties surrounding the deal’s success persist, including speculation as to whether OPEC members will even uphold the agreement. Regardless, OPEC’s deal is significant in many ways. For many oil-producing countries, it could be the catalyst needed to re-invigorate domestic oil production, boost industry morale and stem the downward spiral of bankruptcy and loss. For oil-dependent industries, such as the airline industry, it could mean preparing for potential fluctuations in crude oil prices over the next few months. As for OPEC itself, the deal may either be the saving grace the cartel needs to get itself back on its feet—or its downfall, encouraging the rise of the non-OPEC oil producers it has tried so hard to compete against in the first place.

Charles Dewhurst is partner and co-leader of the Natural Resources practice at BDO. He can be reached at [email protected].
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Top Takeaways from the 2016 Oil & Gas Council North America Assembly

By Jason Taibel

Along with several of my colleagues, I recently attended the 2016 Oil & Gas Council North America Assembly in Houston. The conference, which brought together oil and gas executives across the continent to discuss prominent industry trends and developments, coincided with big news for the oil and gas industry. For the first time in over two years, an exploration and production (E&P) company went public in October. On the heels of an extremely successful IPO, the conference focused on opportunities and challenges for the industry in the year ahead.

Human capital is a valuable—and increasingly scarce—resource in the industry.
As the Baby Boomer generation reaches retirement age, many industries are facing a succession challenge, and the energy industry is no exception. As this demographic ages, the number of skilled workers, such as petroleum engineers, exiting the workforce outweighs the new talent entering. Given the greater concerns around pricing, a human capital deficit is not the top concern in the immediate term. Many companies have emphasized cost-cutting to combat the ripple effects of the downturn. Looking toward the future, however, a deficit of skilled workers could prove challenging. When the market turns around, will there be enough talent to support continued industry growth and expansion?

Innovation and automation is an emerging force in the sector.
While skilled workers will always be vital to the industry’s success, many oil and gas companies are embracing technological advancements to automate, optimize and streamline processes. BP, for example, recently launched an initiative to increase its digital capabilities and gather real-time data from offshore production platforms through cloud and analytics software. Companies that actively leverage new technology and automation capabilities will be able to operate with fewer workers, making them less susceptible to the negative effects of a decreased labor supply.

For M&A deals, executives value areas with growth potential.
Expansion-minded industry executives are focusing on key geographic areas that offer opportunities for profitable mergers and acquisitions. Beyond the areas that are already active deal sites, oil and gas executives are increasingly seeking to identify growth assets, or areas that demonstrate potential for growth when commodity prices resurge. In recent years, there has been an uptick in deal flow as oil prices get closer to $50 per barrel. In the third quarter of 2016, there were 93 deals in the oil and gas industry, totaling $16.6 billion, according to the U.S. Energy Information Administration. At present, the majority of the deals in the energy sector are funded by equity, with energy-focused private equity firms being a key driver of deals, while generalist firms have largely remained on the sidelines.

A few of the major areas in play at the start of 2017 include:
  • The Permian and Delaware Basins continue to be extremely active regions. Throughout the year, there has been a heavy cadence of transactions with high multiples in these two key regions. In fact, it has been difficult to sell conventional assets outside of the Permian and Delaware Basins or Eagle Ford.
  • Environmental factors have led to downturns in deal activity in major onshore regions. Oklahoma, for example, has seen decreased deal activity because of increasing concerns around earthquake exposure. Colorado is also facing a slow deal-making environment as fracking concerns persist in the region. 
  • For companies not already engaged in the U.S. Gulf of Mexico, there are no incentives to enter this highly-regulated region.
  • With respect to Mexico, in the immediate future, oil and gas executives are interested in how US-Mexico relations will evolve with the new presidential administration.
Financial and capital structure concerns continue to disrupt the industry.
It’s no secret that the energy industry has had a difficult few years financially. Since December 2014, about 150 companies have restructured or filed for bankruptcy. Looking toward the future, as U.S. bank regulators continue to limit the amount of credit that U.S banks will have available for reserve based loans, future borrowing base redeterminations may spur more restructuring as liquidity decreases. Companies that initially did some light restructuring in anticipation of a quicker spike in prices may need to restructure again or file bankruptcy.

Certain midstream companies may be the next market segment to restructure, since many of their contracts, which were established during periods of high prices, are set to expire.

The worst is likely behind us.
Barring any catastrophic events, it is unlikely that oil prices will drop to less than $30 per barrel again. Prices are expected to recover, but no one expects a full resurgence to peaks of $100 per barrel. In all likelihood, prices will level off around $55-$60 per barrel. 

The oil and gas industry is still in the mires of a downturn, but there is reason for optimism in the year ahead. Companies that embrace innovation and take strategic measures to consolidate and cut costs will be well-positioned when the market recovers.

Jason Taibel is a partner in BDO’s Houston office, and can be reached at [email protected].
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Q&A with Steve Franckhauser, HBK Energy

Established in 1949, Hill, Barth & King (HBK) CPAs & Consultants offers tax, accounting, assurance and consulting services to a variety of clients in Ohio, New Jersey, Pennsylvania and Florida, and has been a BDO Alliance firm for 14 years, joining more than 400 independent firms in the world’s fifth largest accounting and consulting network.

We recently sat down with Steve Franckhauser, Director of HBK Energy (an affiliated HBK entity), to discuss Steve’s work in the sector and his predictions for industry trends. With over two decades of experience in the energy space, Steve has been with HBK Energy since 2011, assisting natural resources owners, shale businesses, lenders and government entities, developers and others maximize their financial opportunities and investments.

How did you come to specialize in the oil & gas industry?
I was born and reared in the Appalachia region, specifically eastern Ohio. In the mid-1990s, I had the good fortune to cut my teeth in the energy industry as a young lawyer representing a dairy farmer in a lawsuit against a large public utility. Through practicing law in similar cases, I realized I had a true passion for working with privately held companies. Because energy is an essential part of our daily life, it’s something I view more as a vocation than a job.

As I realized where my professional interests lie, I also witnessed what was happening in the region where I was born and raised—the dramatic and painful decline of steel and other material industries. When the shale industry started to take hold in Pennsylvania in the mid-2000s, I saw that as an opportunity for the region to restore itself to prosperity and become an important player in the nation again. At the same time, I was looking for an opportunity to combine my legal and financial experience with my passion for helping private businesses, and HBK proved to be the perfect place to do just that.

Tell us a bit more about your company HBK Energy (HBKE) and the type of work you do, and how that ties into your relationship with BDO USA. 
HBK is a total financial services firm with a wide variety of tax, accounting, assurance and business specialty services. Our footprint is growing beyond the historical base in Appalachia, eastern Pennsylvania, New Jersey and both Florida coasts—and given our service offerings and our regional identity, working with energy and shale clients is a clear opportunity for our firm to support the sector. Our goal is help clients apply their limited resources within the framework of their operations. Our multidisciplinary resources are enhanced by BDO’s expertise and support. We’ve had a relationship with BDO for many years, and our partners are active at seminars, webinars and conferences. We have found this partnership to be mutually beneficial, particularly for our natural resources work.

How would you characterize the current state of the energy industry in the United States, and what do you think lies ahead in the coming year?
When it comes to the domestic energy sector, I prefer the term “evolution” to “revolution.” Most of the country is dedicated to weaning itself off imported oil and coal, but perceptions about this shift vary widely along generational and regional lines.

Despite the obvious shifts and contrary to some of the chatter littering airwaves both in the industry and in the general media, most of what is happening in the energy sector is positive. The energy industry learns from each new challenge. While the presidential election was contentious, energy was not a major point of division. Remarkably, the U.S. is still playing a huge role in the advancement of the global energy industry, and I expect that will continue for years to come.

Looking forward to 2017, I think the sector will continue to evolve. We’ll move towards using cleaner forms of energy, such as natural gas, to power our electrical grid, but figuring out how to maximize the use of our domestic energy supply will prove to be a significant hurdle. While the desire to move away from coal is substantial, the infrastructure needed to support this shift, including refineries, pipelines and generators, is still developing.             

How do you think regulatory action, at the federal and state levels, affects the performance of the industry overall?
There are 51 different regulatory jurisdictions governing the industry—federal and state. In some instances, the differences between these regulations have made certain states more attractive to energy players than others. For example, many of the energy assets in Pennsylvania shifted to Ohio, partially due to Pennsylvania’s proposed severance tax on top of its existing impact “fee.” Conversely, Ohio has not increased its extraction tax rate in recent years—making it a prime target for relocation.

Despite these differences, regulatory changes have been incremental in the Appalachian Basin and cooperation and healthy competition exists. Energy companies seek fair and predictable regulations they can work into their strategic planning. A new chief executive in Washington is the “X” factor. Time will tell if electoral rhetoric will match policy initiatives. At a minimum, HBKE expects a less hands on approach from the new administration.

Are there any areas of the U.S. you expect will play a large role in U.S. energy production next year? 
Texas has long been a good home for energy companies, and the state manages to contribute to the industry’s growth without too much burden on the local landscape. Louisiana also has a large petrochemical presence along the Gulf of Mexico, which is a major source of employment in the state. When it comes to my home Appalachia region, the story has not been written yet. As I had mentioned, Pennsylvania’s impact tax and diverse constituencies have caused many companies to flee to nearby states with less stringent requirements. West Virginia might be poised for a bit of a boom if it proves attractive to Pennsylvania-based companies. Ohio has made major strides toward welcoming the industry, addressing most problems quickly and efficiently, while positioning itself as a regional industry powerhouse. We anticipate the Upper Ohio Valley to spawn a petrochemical industry along the banks of the Ohio River. The gestation period is critical for this industry and much hinges on the subsequent development to the Shell ethane cracker in Pennsylvania and potential other ethane crackers further south in Ohio and West Virginia.

Is there anything else you would like to add?
U.S. energy is growing beyond coal and oil—natural gas, renewable and sustainable energy sources will gain prominence in the energy mix. What happens in the future ultimately comes down to a two-pronged question— what will the consumer demand, and how will the industry work to meet those demands?

When we established HBK Energy, our goal was to include all energy forms within our sphere of influence. Thus, we purposively chose the word “energy” because we did not want to restrict our efforts to oil and gas alone. We sought a much larger seat at the table and included coal, solar, wind and hydro options, among several others, that will be a much larger part of the conversation years from now—simply because the consumer is demanding it and the technology is evolving. To use a sports analogy, you throw the football where the receiver will be, not where he is when you throw the ball. We have a rich history, but our eyes are on the energy industry of the future.

For more information on HBK Energy, visit their website:

Steve Franckhauser can be reached at [email protected].

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PErspective in Natural Resources

A feature examining the role of private equity in the natural resources sector.

Consolidation is picking up in the midstream oil and gas sector as oil prices slowly rise and several players look to M&A to achieve growth. Year-over-year, M&A activity has remained much the same, but there has been a significant uptick in dealmaking in the third quarter, driven in part by crude’s price topping $50 a barrel for several consecutive weeks, according to energy newsletter Rigzone.

Read the Perspective Natural Resources Article

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For more information on BDO USA's service offerings to this industry, please contact one of the following practice leaders:

Charles Dewhurst


Jim Johnson

Kevin Hubbard

  Rafael Ortiz


Richard Bogatto 

  Clark Sackschewsky



Tom Elder 


Chris Smith
Los Angeles


Vicky Gregorcyk 


Alan Stevens 


Rocky Horvath


Jim Willis 


[1] OPEC 171st Meeting concludes. (2016, November 30). Retrieved from
[2] Hjelmgaard, K., & Bomey, N. (2016, November 30). OPEC agrees to oil production cuts. Retrieved from
[3] DiChristopher, T. (2016, November 30). The OPEC deal is done. Here’s what to expect from oil markets next. Retrieved from
[4] Krauss, C. (2016, December 1). Oil Prices: What’s Behind the Volatility? Simple Economics. The New York Times. Retrieved from
[5] DiChristopher, T. (2016, November 30).